In drilling a borehole in the earth, such as for the recovery of hydrocarbons or for other applications, it is conventional practice to connect a drill bit on the lower end of an assembly of drill pipe sections that are connected end-to-end so as to form a “drill string.” The bit is rotated by rotating the drill string at the surface or by actuation of downhole motors or turbines, or by both methods. With weight applied to the drill string, the rotating bit engages the earthen formation causing the bit to cut through the formation material by either abrasion, fracturing, or shearing action, or through a combination of all cutting methods, thereby forming a borehole along a predetermined path toward a target zone.
Many different types of drill bits have been developed and found useful in drilling such boreholes. Two predominate types of drill bits are roller cone bits and fixed cutter (or rotary drag) bits. Most fixed cutter bit designs include a plurality of blades angularly spaced about the bit face. The blades project radially outward from the bit body and form flow channels therebetween. In addition, cutting elements are typically grouped and mounted on several blades in radially extending rows. The configuration or layout of the cutting elements on the blades may vary widely, depending on a number of factors, such as the formation to be drilled.
The cutting elements disposed on the blades of a fixed cutter bit are typically formed of extremely hard materials. In a typical fixed cutter bit, each cutting element includes an elongate and generally cylindrical tungsten carbide substrate that is received and secured in a pocked formed in the surface of one of the blades. The cutting elements typically include a hard cutting layer of polycrystalline diamond (“PCD”) or other superabrasive materials such as thermally stable diamond or polycrystalline cubic boron nitride. For convenience, as used herein, reference to “PDC bit” or “PDC cutters” refers to a fixed cutter bit or cutting element employing a hard cutting layer of polycrystalline diamond or other superabrasive materials.
Referring to FIGS. 1 and 2, a conventional fixed cutter or drag bit 10 adapted for drilling through formations of rock to form a borehole is shown. The bit 10 generally includes a bit body 12, a shank 13, and a threaded connection or pin 14 at a pin end 16 for connecting the bit 10 to a drill string (not shown) that is employed to rotate the bit in order to drill the borehole. The bit face 20 supports a cutting structure 15 and is formed on the end of the bit 10 that is opposite the pin end 16. The bit 10 further includes a central axis 11 about which the bit 10 rotates in the cutting direction represented by arrow 18.
A cutting structure 15 is provided on the face 20 of the bit 10. The cutting structure 15 includes a plurality of angularly spaced-apart primary blades 31, 32, 33, and secondary blades 34, 35, 36, each of which extends from the bit face 20. The primary blades 31, 32, 33 and the secondary blades 34, 35, 36 extend generally radially along the bit face 20 and then axially along a portion of the periphery of the bit 10. However, the secondary blades 34, 35, 36 extend radially along the bit face 20 from a position that is distal the bit axis 11 toward the periphery of the bit 10. Thus, as used herein, “secondary blade” may be used to refer to a blade that begins at some distance from the bit axis and extends generally radially along the bit face to the periphery of the bit. The primary blades 31, 32, 33 and the secondary blades 34, 35, 36 are separated by drilling fluid flow courses 19.
Referring still to FIGS. 1 and 2, each primary blade 31, 32, 33 includes blade tops 42 for mounting a plurality of cutting elements, and each secondary blade 34, 35, 36 includes blade tops 52 for mounting a plurality of cutting elements. In particular, cutting elements 40, each having a cutting face 44, are mounted in pockets formed in blade tops 42, 52 of each primary blade 31, 32, 33 and each secondary blade 34, 35, 36, respectively. Cutting elements 40 are arranged adjacent one another in a radially extending row proximal the leading edge of each primary blade 31, 32, 33 and each secondary blade 34, 35, 36. Each cutting face 44 has an outermost cutting tip 44a furthest from the blade tops 42, 52 to which the cutting elements 40 are mounted.
Referring now to FIG. 3, a profile of bit 10 is shown as it would appear with all blades (e.g., primary blades 31, 32, 33 and secondary blades 34, 35, 36) and cutting faces 44 of all cutting elements 40 rotated into a single rotated profile. In rotated profile view, blade tops 42, 52 of all blades 31-36 of the bit 10 form and define a combined or composite blade profile 39 that extends radially from the bit axis 11 to the outer radius 23 of the bit 10. Thus, as used herein, the phrase “composite blade profile” refers to the profile, extending from the bit axis to the outer radius of the bit, formed by the blade tops of all the blades of a bit rotated into a single rotated profile (i.e., in rotated profile view).
The conventional composite blade profile 39 (most clearly shown in the right half of bit 10 in FIG. 3) may generally be divided into three regions conventionally labeled cone region 24, shoulder region 25, and gage region 26. The cone region 24 includes the radially innermost region of the bit 10 and the composite blade profile 39 extending generally from the bit axis 11 to the shoulder region 25. As shown in FIG. 3, in most conventional fixed cutter bits, the cone region 24 is generally concave. Adjacent the cone region 24 is the shoulder (or the upturned curve) region 25. In most conventional fixed cutter bits, the shoulder region 25 is generally convex. Moving radially outward, adjacent the shoulder region 25 is the gage region 26 which extends parallel to the bit axis 11 at the outer radial periphery of the composite blade profile 39. Thus, the composite blade profile 39 of the conventional bit 10 includes one concave region, cone region 24, and one convex region, shoulder region 25.
The axially lowermost point of the convex shoulder region 25 and the composite blade profile 39 defines a blade profile nose 27. At the blade profile nose 27, the slope of a tangent line 27a to the convex shoulder region 25 and the composite blade profile 39 is zero. Thus, as used herein, the term “blade profile nose” refers to the point along a convex region of a composite blade profile of a bit in rotated profile view at which the slope of a tangent to the composite blade profile is zero. For most conventional fixed cutter bits (e.g., bit 10), the composite blade profile includes only one convex shoulder region (e.g., convex shoulder region 25), and only one blade profile nose (e.g., nose 27). As shown in FIGS. 1-3, the cutting elements 40 are arranged in rows along the blades 31-36 and are positioned along the bit face 20 in the regions previously described as cone region 24, shoulder region 25 and gage region 26 of the composite blade profile 39. In particular, the cutting elements 40 are mounted on the blades 31-36 in predetermined radially-spaced positions relative to the central axis 11 of the bit 10.
Without regard to the type of bit, the cost of drilling a borehole is proportional to the length of time it takes to drill the borehole to the desired depth and location. The drilling time, in turn, is greatly affected by the number of times the drill bit is changed before reaching the targeted formation. This is the case because each time the bit is changed, the entire drill string, which may be miles long, must be retrieved from the borehole section by section. Once the drill string has been retrieved and the new bit installed, the bit must be lowered to the bottom of the borehole on the drill string, which again, must be constructed section by section. This process, known as a “trip” of the drill string, generally requires considerable time, effort, and expense. Accordingly, it is desirable to employ drill bits that will drill faster and longer and that are usable over a wider range of differing formation hardnesses.
The length of time that a drill bit may be employed before it is changed depends upon its rate of penetration (“ROP”), as well as its durability or ability to maintain a high or acceptable ROP. Additionally, a desirable characteristic of the bit is that it be “stable” and resist undesirable vibration, the most severe type or mode of which is “whirl,” which is a term used to describe the phenomenon where a drill bit rotates at the bottom of the borehole about a rotational axis that is offset from the geometric center of the drill bit. Such whirling subjects the cutting elements on the bit to increased loading, which causes premature wearing or destruction of the cutting elements and a loss of ROP. Thus, preventing or reducing undesirable bit vibration and maintaining stability of PDC bits has long been a desirable goal, but one that has not always been achieved. Undesirable bit vibration typically may occur in any type of formation, but is most detrimental in harder formations.
In recent years, the PDC bit has become an industry standard for cutting formations of soft and medium hardnesses. However, as PDC bits are being developed for use in harder formations, bit stability is becoming an increasing challenge. As previously described, excessive undesirable bit vibration during drilling tends to dull the bit and/or may damage the bit to an extent that a premature trip of the drill string becomes necessary or desired.
There have been a number of alternative designs proposed for PDC cutting structures that were meant to provide a PDC bit capable of drilling through a variety of formation hardnesses at effective ROPs and with acceptable bit life or durability. Unfortunately, many of the bit designs aimed at minimizing vibration require that drilling be conducted with an increased weight-on-bit (“WOB”) as compared to bits of earlier designs. For example, some bits have been designed with cutters mounted at less aggressive back rake angles such that they require increased WOB in order to penetrate the formation material to the desired extent. Drilling with an increased or heavy WOB is generally avoided if possible. Increasing the WOB is accomplished by adding additional heavy drill collars to the drill string. This additional weight increases the stress and strain on some or all drill string components, causes stabilizers to wear more and to work less efficiently, and increases the hydraulic drop in the drill string, requiring the use of higher capacity (and typically higher cost) pumps for circulating the drilling fluid. Compounding the problem still further, the increased WOB causes the bit to wear and become dull more quickly than would otherwise occur. In order to postpone tripping the drill string, it is common practice to add further WOB and to continue drilling with the partially worn and dull bit. The relationship between bit wear and WOB is not linear, but is an exponential one, such that upon exceeding a particular WOB for a given bit, a very small increase in WOB will cause a tremendous increase in bit wear. Thus, adding more WOB so as to drill with a partially worn bit further escalates the wear on the bit and other drill string components.